Zeolite-containing drilling fluids

ABSTRACT

Methods and compositions for wellbore treating fluids, especially drilling fluids, that comprise zeolite and a carrier fluid.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of prior application Ser. No.10/795,158 filed Mar. 5, 2004, the entire disclosure of which isincorporated herein by reference, which is a continuation-in-part ofprior application Ser. No. 10/738,199 filed Dec. 17, 2003, the entiredisclosure of which is incorporated herein by reference, which is acontinuation-in-part of prior application Ser. No. 10/727,370 filed Dec.4, 2003, the entire disclosure of which is incorporated herein byreference, which is a continuation-in-part of prior application Ser. No.10/686,098 filed Oct. 15, 2003, now U.S. Pat. No. 6,964,302 issued Nov.15, 2006, the entire disclosure of which is incorporated herein byreference, which is a continuation-in-part of prior application Ser. No.10/623,443 filed Jul. 18, 2003, the entire disclosure of which isincorporated herein by reference, and which is a continuation-in-part ofprior application Ser. No. 10/315,415, filed Dec. 10, 2002, now U.S.Pat. No. 6,989,057 issued Jan. 24, 2006, the entire disclosure of whichis incorporated herein by reference.

BACKGROUND

The present embodiment relates generally to a treating fluid,particularly a drilling fluid, for introduction into a subterranean zonepenetrated by a wellbore.

Conventionally, a wellbore is drilled into a subterranean zone using adrilling fluid that is circulated through the wellbore. During thedrilling of a wellbore, the drilling fluid is continuously circulateddown the drill pipe, through the drill bit, and back to the surfacethrough the annulus between the drill pipe and the walls of thewellbore. After a wellbore has been drilled to total depth, thecirculation of the drilling fluid is stopped (called a “shut-downperiod”), while the well is logged and pipe is run in the wellbore.

One function of a drilling fluid is to seal off the walls of thewellbore so that the fluid is not lost into highly permeablesubterranean zones penetrated by the wellbore. During the shut downperiod, this is accomplished by the deposit of a filter cake of solidsfrom the drilling fluid, and additional dehydrated drilling fluid andgelled drilling fluid, on the walls of the wellbore.

After the pipe is run in the wellbore, the drilling fluid in thewellbore is cleaned up by re-initiating circulation of drilling fluid.The drilling fluid is circulated downwardly through the interior of thepipe and upwardly through the annulus between the exterior of the pipeand the walls of the wellbore, while removing drilling solids, gas,filter cake, dehydrated drilling fluid, gelled drilling fluid, cuttings,and any other debris needing to be removed from the wellbore. Thus, adrilling fluid must be capable of transporting a sufficient amount ofcuttings and other debris through the annulus and up to the surface inorder to provide a clean wellbore for subsequent cementing operations.

After the wellbore is cleaned by the drilling fluid, primary cementingoperations are performed therein. Namely, the pipe is cemented in thewellbore by placing a cement slurry in the annulus between the pipe andthe walls of the wellbore. The cement slurry sets into a hardimpermeable mass, and is intended to bond the pipe to the walls of thewellbore whereby the annulus is sealed and fluid communication betweensubterranean zones or to the surface by way of the annulus is prevented.

As a result of the polymeric viscosifiers and additives typically usedin drilling fluids, the filter cake formed is generally very stable andcan be difficult to remove. However, removal of the gelled anddehydrated drilling fluid and filter cake from the walls of the wellboreand displacement of the drilling fluid from the wellbore must take placeprior to primary cementing operations in order to achieve a satisfactorybond between the pipe, primary cement and the walls of the wellbore.

Heretofore, attempts have been made to remove the drilling fluid andfilter cake from the wellbore by attaching mechanical scrapers to thepipe so that as the pipe is run into the well bore, it physicallycontacts and breaks up some of the drilling fluid and filter cake. Inaddition, flushes are normally run through the annulus between the pipeand the walls of the wellbore prior to cementing in order to removedrilling fluid and filter cake therein. It is also known to use spacerfluids in oil and gas wells to displace drilling fluids and removefilter cake deposits from the walls of the wellbore. Other methods forremoving drilling fluid and filter cake from the wellbore includepumping fluids through the annulus at high rates so that they are inturbulence as they contact the filter cake, and including surfactants inflush fluids to lower surface tension and enhance the penetration of theflush fluids into the filter cake. If appreciable drilling fluid andfilter cake remain on the walls of the wellbore, primary cementingoperations are less than satisfactory, as the cement will not properlybond to the walls of the wellbore and fluid leakage through the annulusand other major problems can result.

Still other methods for achieving satisfactory primary cementingoperations when deposits of filter cake are an issue include laying downa settable filter cake on the walls of the wellbore and activating thefilter cake to harden and set up. Thus, any remaining filter cake isless likely to interfere with primary cementing operations.

DESCRIPTION

According to certain embodiments described herein, methods are providedfor circulating a drilling fluid comprising zeolite and a carrier fluidthrough a wellbore.

According to still other embodiments described herein, methods areprovided for using zeolite as a suspending agent in a drilling fluid,whereby the drilling fluid has sufficient carrying capacity andthixotropy to transport cuttings through the annulus and out to thesurface. According to such embodiments, the zeolite acts as a suspendingagent for one or more of cuttings, a weighting agent, and losscirculation material. Examples of loss circulation materials includeclay and aqueous rubber latex or hydratable polymers (e.g., U.S. Pat.Nos. 5,913,364; 6,060,434; 6,167,967; 6,258,757, the entire disclosuresof which are incorporated herein by reference), which form masses thatseal the space fractures, vugs, thief zones and the like in a wellbore.

According to still other embodiments described herein, portions of azeolite-containing drilling fluid are left on the walls of a wellbore aspart of a filter cake, and/or in permeable areas affecting the wellbore,such as fissures, fractures, caverns, vugs, thief zones, low pressuresubterranean zones or high pressure subterranean zones. According tosuch an embodiment, the zeolite in the portions of the drilling fluidleft in the wellbore acts as a settable material, which can be caused toset by an activator. According to one embodiment, a subsequentcomposition that contains at least one activator is pumped into thewellbore to come into contact with the drilling fluid left therein. Inone such embodiment, the subsequent composition containing at least oneactivator is a treating fluid, such as a mud, pill, or spotting fluid,and is pumped into the wellbore prior to primary cementing operations.According to another embodiment, the subsequent composition containingat least one activator is a cement slurry pumped into the wellboreduring cementing operations.

When the activator in the subsequent composition contacts the drillingfluid in the filter cake and/or permeable areas, the activator causesthe zeolite in the drilling fluid to set. In addition, when thesubsequent composition is a cement slurry, as the cement slurry sets,the activator therein diffuses into the drilling fluid left in thefilter cake and/or permeable areas in the wellbore.

The activator is present in the subsequent composition in a compressivestrength-developing amount, and may be one or more of calcium hydroxide,calcium oxide, calcium nitrate, sodium silicate, sodium fluoride, sodiumsilicofluoride, magnesium silicofluoride, zinc silicofluoride, sodiumcarbonate, potassium carbonate, sodium hydroxide, potassium hydroxide,sodium sulfate, and mixtures thereof. Selection of the type and amountof an activator(s) largely depends on the type and make-up of thecomposition in which the activator is contained, and it is within themeans of those of ordinary skill in the art to select a suitable typeand amount of activator.

Thus, according to the present embodiments, zeolite left in a wellboreby a zeolite-containing drilling fluid can be caused to set by anactivator in a composition placed in the wellbore subsequent to thedrilling fluid. Zeolite that sets in permeable areas affecting thewellbore, such as fissures, fractures, caverns, vugs, thief zones, lowpressure subterranean zones or high pressure subterranean zoneseffectively seals such permeable areas, thereby preventing the entry orflow of formation fluids into the annulus. In addition, because drillingfluid does not set, its removal is a concern for subsequent cementingoperations. Causing the zeolite left in the wellbore by the drillingfluid to set creates conditions more favorable for primary cementingoperations, as well as reduces the need for other fluids or methodsconventionally used to remove drilling fluid and/or filtercake from awellbore.

Other embodiments described herein provide a drilling fluid comprisingzeolite and a carrier fluid. Drilling fluids according to the suchembodiments provide sufficient carrying capacity and thixotropy totransport cuttings to the surface and prevent the cuttings from settlingappreciably when circulation is interrupted.

Zeolites are porous alumino-silicate minerals that may be either anatural or manmade material. Manmade zeolites are based on the same typeof structural cell as natural zeolites and are composed ofaluminosilicate hydrates having the same basic formula as given below.It is understood that as used in this application, the term “zeolite”means and encompasses all natural and manmade forms of zeolites. Allzeolites are composed of a three-dimensional framework of SiO₄ and AlO₄in a tetrahedron, which creates a very high surface area. Cations andwater molecules are entrained into the framework. Thus, all zeolites maybe represented by the crystallographic unit cell formula:M_(a/n)[(AlO₂)_(a)(SiO₂)_(b)]·xH₂Owhere M represents one or more cations such as Na, K, Mg, Ca, Sr, Li orBa for natural zeolites and NH₄, CH₃NH₃, (CH₃)₃NH, (CH₃)₄N, Ga, Ge and Pfor manmade zeolites; n represents the cation valence; the ratio of b:ais in a range from greater than or equal to 1 and less than or equal to5; and x represents the moles of water entrained into the zeoliteframework.

Zeolites suitable for use in a drilling fluid according to the presentembodiments include analcime (hydrated sodium aluminum silicate),bikitaite (lithium aluminum silicate), brewsterite (hydrated strontiumbarium calcium aluminum silicate), chabazite (hydrated calcium aluminumsilicate), clinoptilolite (hydrated sodium aluminum silicate), faujasite(hydrated sodium potassium calcium magnesium aluminum silicate),harmotome (hydrated barium aluminum silicate), heulandite (hydratedsodium calcium aluminum silicate), laumontite (hydrated calcium aluminumsilicate), mesolite (hydrated sodium calcium aluminum silicate),natrolite (hydrated sodium aluminum silicate), paulingite (hydratedpotassium sodium calcium barium aluminum silicate), phillipsite(hydrated potassium sodium calcium aluminum silicate), scolecite(hydrated calcium aluminum silicate), stellerite (hydrated calciumaluminum silicate), stilbite (hydrated sodium calcium aluminum silicate)and thomsonite (hydrated sodium calcium aluminum silicate). According tocertain embodiments, the zeolite is one of chabazite and clinoptilolite.

According to one embodiment, the drilling fluid includes zeolite in anamount of from about 1% to about 50% by volume. According to anotherembodiment, the drilling fluid includes zeolite in an amount of fromabout 5% to about 20% by volume. According to yet another embodiment,the drilling fluid includes zeolite in an amount of from about 8% toabout 15% by volume.

According to still other embodiments described herein, a drilling fluidcomprises zeolite and a carrier fluid, and further comprises one or moreof a weighting agent, a filtrate control agent, a dispersant, losscirculation material, a surfactant (such as an emulsifier or a foamingagent), a de-air entraining agent and a lubricant. In addition, adrilling fluid according to the present embodiments can comprise zeoliteand a carrier fluid, and can further comprise a viscosifier.

As used herein the term “viscosifier” means any agent that increases theviscosity of a fluid. In a drilling fluid, viscosifiers add viscosity tothe drilling fluid to impart sufficient carrying capacity andthixotropy, whereby the drilling fluid can transport cuttings out of thewellbore to the surface, and prevent cuttings from settling appreciablywhen circulation of the drilling fluid is interrupted. In the presentembodiments, the zeolite provides the drilling fluid with suspensionproperties, and therefore is a suitable replacement for conventionalviscosifiers. However, the zeolite can also be used in conjunction withconventional viscosifiers known to those of ordinary skill in the art.

Agents which are useful as conventional viscosifiers include, but arenot limited to, clays; polymeric additives, whether natural orsynthetic; modified cellulose and derivatives thereof; guar gum;diatomaceous earth; and starches. The choice of a viscosifier dependsupon the viscosity desired, chemical capability with other fluids usedin formation of the wellbore, and other wellbore design concerns.

Clays suitable for use as viscosifiers include kaolinites,montmorillonite, bentonite, hydrous micas, attapulgite, sepiolite, andthe like and also synthetic clays, such as laponite.

Polymeric additives suitable for use as a viscosifier in the presentembodiments include polymers which contain, in sufficient concentrationand reactive position, one or more hydroxyl, cis-hydroxyl, carboxyl,sulfate, sulfonate, amino or amide functional groups. Particularlysuitable polymers include polysaccharides and derivatives thereof whichcontain one or more of the following monosaccharide units: galactose,mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronicacid or pyranosyl sulfate. Natural polymers containing the foregoingfunctional groups and units include guar gum and derivatives thereof,locust bean gum, tara, konjak, starch, cellulose, karaya gum, xanthangum, tragacanth gum, arabic gum, ghatti gum, tamarind gum, carrageenanand derivatives thereof. Synthetic polymers and copolymers that aresuitable for use as a viscosifier in the present embodiments include,but are not limited to, polyacrylate, polymethacrylate, polyacrylamide,maleic anhydride, methylvinyl ether copolymers, polyvinyl alcohol andpolyvinylpyrrolidone.

Modified gums such as carboxyalkyl derivatives, like carboxymethyl guar,and hydroxyalkyl derivatives, like hydroxypropyl guar are also suitableviscosifiers. Doubly derivatized gums such as carboxymethylhydroxypropylguar (CMHPG) are also suitable viscosifiers.

Modified celluloses and derivatives thereof, for example, celluloseethers, esters and the like can also be used as a viscosifier of thewellbore treating fluids of the present embodiment. In general, any ofthe water-soluble cellulose ethers can be used. Those cellulose ethersinclude, among others, the various carboxyalkylcellulose ethers, such ascarboxyethylcellulose and carboxymethylcellulose (CMC); mixed etherssuch as carboxyalkylethers, e.g., carboxymethylhydroxyethylcellulose(CMHEC); hydroxyalkylcelluloses such as hydroxyethylcellulose (HEC) andhydroxypropylcellulose; alkylhydroxyalkylcelluloses such asmethylhydroxypropylcellulose; alkylcelluloses such as methylcellulose,ethylcellulose and propylcellulose; alkylcarboxyalkylcelluloses such asethylcarboxymethylcellulose; alkylalkylcelluloses such asmethylethylcellulose; hydroxyalkylalkylcelluloses such ashydroxypropylmethylcellulose; and the like.

Preferred polymeric additives for use as a viscosifer with theembodiments disclosed herein include those selected from the groupconsisting of welan gum, xanthan gum, galactomannan gums, succinoglycangums, scleroglucan gums, and cellulose and its derivatives, particularlyhydroxyethylcellulose.

In one embodiment where the drilling fluid comprises zeolite, a carrierfluid, and a viscosifier, the drilling fluid includes the viscosifier inan amount of up to about 5% by volume. In another embodiment, thedrilling fluid includes the viscosifier in an amount of from about 0.5%to about 2.5% by volume.

In still another embodiment, a drilling fluid includes zeolite, acarrier fluid and a filtrate loss control additive in an amount of fromabout 0.01% to about 2.5% by volume. According to another embodiment,the drilling fluid includes a filtrate loss control additive in anamount of from about 0.1% to about 1.0% by volume.

In yet another embodiment, the drilling fluid comprises zeolite, acarrier fluid and a dispersant. Suitable dispersants include thoseselected from the group consisting of sulfonated styrene maleicanhydride copolymer, sulfonated vinyltoluene maleic anhydride copolymer,sodium naphthalene sulfonate condensed with formaldehyde, sulfonatedacetone condensed with formaldehyde, lignosulfonates and interpolymersof acrylic acid, allyloxybenzene sulfonate, allyl sulfonate andnon-ionic monomers. According to one such embodiment, the drilling fluidincludes from about 0.02% to about 6.0% by volume of a dispersant, andaccording to another such embodiment from about 0.1% to about 2.0% byvolume of a dispersant.

According to still other embodiments, a drilling fluid comprises zeoliteand a carrier fluid, and further comprises a weighting agent. Preferredweighting agents include those selected from the group consisting ofbarium sulfate, also known as “barite”, hematite, manganese tetraoxide,galena, ilmenite and calcium carbonate. According to one suchembodiment, a weighting agent is present in a drilling fluid in anamount up to about 97% by volume, and according to another suchembodiment, in an amount of from about 2% to about 57% by volume.

Carrier fluids suitable for use in the embodiments of drilling fluidsdisclosed herein comprise an aqueous fluid, such as water andwater-based gels, oil-based and synthetic-based fluids, emulsions,acids, or mixtures thereof. Exemplary oil-based fluids include but arenot limited to canola oil, kerosene, diesel oil, fish oil, mineral oil,sunflower oil, corn oil, soy oil, olive oil, cottonseed oil, peanut oiland paraffin. Exemplary synthetic-based fluids include but are notlimited to esters, olefins and ethers.

According to certain embodiments, a carrier fluid or mixture thereof ispresent in the drilling fluid in an amount of from about 3% to about 98%by volume. According to other embodiments, a carrier fluid or mixturethereof is present in an amount of from about 50% to about 92% byvolume. According to still other embodiments, a carrier fluid or mixturethereof is present in an amount of from about 80% to about 90% byvolume. The preferred carrier fluid depends upon the properties desiredfor the drilling fluid and the cost, availability, temperaturestability, viscosity, clarity, and the like of the carrier fluid. Basedon cost and availability, water is preferred. When the carrier fluid iswater, the water can be fresh water, unsaturated salt solution,including brines and seawater, or saturated salt solution.

According to still other embodiments, a method of performing drillingoperations is provided, where the method includes circulating a drillingfluid comprising zeolite and a carrier fluid in a wellbore penetrating asubterranean zone. According to certain examples of such methods, thezeolite is present in the drilling in an amount from about 1% to about50% by volume, or from about 5% to about 20% by volume, or from about 8%to about 15% by volume.

According to still other embodiments, a method of performing drillingoperations is provided, where the method includes circulating a drillingfluid comprising zeolite and a carrier fluid in a wellbore penetrating asubterranean zone, and suspending, in the drilling fluid, one or more ofcuttings, a weighting agent, and loss circulation material. According tosuch methods, the zeolite acts as a suspending agent for the cuttings,weighting agent, or loss circulation material.

Still other embodiments provide a method of performing drillingoperations that includes penetrating a subterranean zone with awellbore, circulating a drilling fluid comprising zeolite and a carrierfluid in the wellbore, leaving a portion of the drilling fluid in thewellbore, and causing the zeolite in the remaining portion of thedrilling fluid to set. In certain examples of such methods, the zeoliteis caused to set by placing a subsequent composition that has acompressive strength-developing amount of an activator in the wellbore,(such as calcium hydroxide, sodium silicate, sodium fluoride, sodiumsilicofluoride, magnesium silicofluoride, zinc silicofluoride, sodiumcarbonate, potassium carbonate, sodium hydroxide, potassium hydroxide,sodium sulfate), and contacting the zeolite in the remaining portion ofthe drilling fluid with the activator. The subsequent composition insuch examples can be a cement slurry, a mud, a spotting fluid, or a pillthat includes the activator.

The following examples are illustrative of the methods and compositionsdiscussed above.

EXAMPLE 1

Five water-based drilling fluids (“Fluids 1-5”) were prepared bycombining the components as set forth in TABLE 1A below. The componentslisted in Table 1A were added one at a time to the carrier fluid (water)in a Waring blender at an rpm where the vortex was evident, usuallybetween 2000-4000 rpm, in intervals of 15 seconds. After all thecomponents had been added to the carrier fluid, the fluid was thenblended for 2 minutes at 2000-4000 rpm.

Bentonite, barite (also known as barium sulfate), caustic soda and lime,as well as sources of same, are widely commercially available chemicalsthat are well known to those of ordinary skill in the art. Bentonite,was the primary viscosifer contributing suspension properties to thefluids in which it was used (Fluids 1 and 4).

CFR-3 is the tradename for a dispersant comprising the condensationproduct of formaldehyde, acetone and a sulfite, and is commerciallyavailable from Halliburton Energy Services.

Biozan was used in this example to provide filtrate control, but isgenerally known as a viscosifier comprising a clarified xanthan gum.Biozan is commercially available from GEO Drilling Fluids, Inc. As aviscosifier, Biozan contributed some suspension properties to the fluidsin which it was used. However, the relative amounts of Biozan to theprimary viscosifier (bentonite in Fluids 1 and 4, zeolite in Fluids 2, 3and 5) is such that the viscosifying effect of the Biozan is secondaryto the viscosifying effect of the primary viscosifier.

CARBONOX is the tradename for a lignite material that is commerciallyavailable from Baroid Drilling Fluids, and is used in this example as afiltrate control additive.

FWCA was used in this example to provide filtrate control, and isgenerally known as a free water control additive comprising cellulosethat is commercially available from Halliburton Energy Services. As acellulose, FWCA contributed some suspension properties to the fluids inwhich it was used. However, the relative amounts of FWCA to the primaryviscosifier (zeolite in Fluids 2, 3 and 5) is such that the viscosifyingeffect of the FWCA is secondary to the viscosifying effect of theprimary viscosifier.

Chabazite, which is commercially available from C2C Zeolite Corporationof Calgary, Canada was the zeolite in Fluids 2, 3 and 5, and was used asthe primary viscosifer to contribute suspension properties to thefluids.

The components were added as described herein on the basis of percent byvolume of the total drilling fluid composition. Fluids 1 and 4 areexemplary of conventional water-based drilling fluids, while Fluids 2,3, 5 are exemplary of water-based drilling fluids containing zeoliteaccording to the present embodiments. Moreover, Fluids 1-3 are exemplaryof lime and water-based drilling fluids, while Fluids 4 and 5 areexemplary of gel and water-based fluids. TABLE 1A Water Based DrillingFluids Component Type Component Function (% by volume) Fluid 1 Fluid 2Fluid 3 Fluid 4 Fluid 5 viscosifier Bentonite 1.96 0 0 0.98 0 weightingagent Barite 7.17 2.52 4.6 8.16 2.52 alkalinity source Caustic soda 0.130 0 0.01 0 alkalinity source Lime 0.05 0.05 0.05 0 0 dispersant CFR-3 00 0 0 0.08 filtrate control, with some Biozan 0 0.20 0 0.22 0.20viscosifying effects filtrate control CARBONOX 0.13 0 0 0 0 filtratecontrol, with some FWCA 0 0.18 0.18 0 0 viscosifying effects viscosifierZeolite (Chabazite) 0 12.20 8.90 0 12.20 Water 90.56 85.05 86.27 90.6384.99 Density (lb/gal) 10.55 10.24 10.47 10.68 10.23

Two oil-based drilling fluids (“Fluids 6-7”) were prepared by combiningthe components as set forth in TABLE 1B below. The carrier fluid forFluids 6 and 7 was diesel oil. As to the preparation of Fluids 6 and 7,lime was added to the carrier fluid in a Waring blender at 6000 rpm, andmixed for 1 minute. The EZMUL NT and the INVERMUL NT were added, andmixing was continued for an additional minute.

Water was then added in the indicated amount, and the rpm was increasedto 12,000 rpm for 2 minutes to form an emulsion. The other componentslisted in Table 1B for Fluids 6 and 7, namely, the barite, lime,zeolite, GELTONE II, calcium chloride and Arquad T-50 were then added asindicated at 6,000 rpm over 1 minute intervals. When all the componentshad been added, the drilling fluid was mixed for about a minute at 6000rpm.

Barite, lime, and calcium chloride as well as sources of same, arewidely commercially available chemicals that are well known to those ofordinary skill in the art.

GELTONE II was the viscosifer used to contribute suspension propertiesto the fluids in which it was used (Fluid 6). The precise chemicaldescription of GELTONE II is not known, however it is known to be atreated clay that functions as a viscosifier, and is commerciallyavailable from Baroid Drilling Fluids.

Arquad T-50™ is a trimethyltallow ammonium chloride (50% active)surfactant that is commercially available from Armak IndustrialChemicals Division.

The precise chemical description of EZMUL NT and the INVERMUL NT is notknown, however the function of each is as an emulsifier, and each iscommercially available from Baroid Drilling Fluids.

Chabazite, which is commercially available from C2C Zeolite Corporationof Calgary, Canada was the zeolite in Fluid 7, and was used in place ofa conventional viscosifier, such as GELTONE II, to contribute suspensionproperties to the fluid. As noted above, the precise chemicalcomposition of GELTONE II is not known, however it is known to be atreated clay. If the zeolite used in Fluid 7 had been treated in thesame manner as GELTONE II, the amount of GELTONE II in Fluid 6 andzeolite in Fluid 7 would be more similar than the amounts indicated inTable 1B.

The components of Fluids 6 and 7 were added as described herein on thebasis of percent by volume of the total drilling fluid composition.Fluid 6 is exemplary of conventional oil-based drilling fluids, whileFluid 7 is exemplary of oil-based drilling fluids containing zeoliteaccording to the present embodiments. TABLE 1B Oil Based Drilling FluidsComponent Component Function (% by volume) Fluid 6 Fluid 7 weightingagent Barite 8.51 0.47 alkalinity source Lime 0.26 0.25 viscosiferZeolite (Chabazite) 0 19.76 emulsifier INVERMUL NT 1.64 1.58 viscosiferGELTONE II 0.16 0 salinity source Calcium chloride 0 0.15 surfactantArquad T-50 0 0.10 emulsifier EZMUL NT 0.21 0.20 Water 21.57 20.7 Diesel67.66 56.8 Density (lb/gal) 9.84 9.83

Fluids 2, 3, 5 and 7 indicated in Tables 1A and 1B are merely exemplaryof the present embodiments. It is within the means of those of ordinaryskill in the art to select different additives than those listed inTables 1A and 1B, as well as different amounts than those listed inTables 1A and 1B. Thus, one of ordinary skill in the art could, withoutunreasonable experimentation, formulate a drilling fluid comprisingzeolite with any of a number of additives, such as weighting agents,viscosifiers, filtrate control agents, dispersants, emulsifiers,surfactants, foaming agents, de-air entraining agents, loss circulationmaterial and lubricants, in order to achieve desired suspensionproperties for a given application.

EXAMPLE 2

Example 2 illustrates the use of zeolite as a suspending agent indrilling fluids according to the present embodiments.

Fluids 1-7 from Example 1 were tested to assess settling and todetermine Theological data, from which yield point and plastic viscosityvalues could be calculated. The Theological data for Fluids 1-5 wasdetermined according to Section 2 of API Specification RP 13B, 12^(th)Edition, 1988, of the American Petroleum Institute (the entiredisclosure of which is hereby incorporated as if reproduced in itsentirety). The Theological data for Fluids 6-7 was determined accordingto Section 2 of API Specification RP 13B-2, 2^(nd) Edition, 1991, of theAmerican Petroleum Institute (the entire disclosure of which is herebyincorporated as if reproduced in its entirety).

When considering the suspension properties of a drilling fluid,rheological data is not conclusive. To more fully assess the suspensionproperties of a drilling fluid, the rheological data must be expressedin terms of plastic viscosity and yield point. Thus, the plasticviscosity and yield point of the water-based fluids (Fluids 1-5) werecalculated from the determined rheological data according tocalculations described in Section 2 of API Specification RP 13B, 12^(th)Edition, 1988, of the American Petroleum Institute. The plasticviscosity and yield point for the oil-based fluids (Fluids 6-7) werecalculated from the determined rheological data according tocalculations described in Section 2 of API Specification RP 13B-2,2^(nd) Edition, 1991, of the American Petroleum Institute.

Settling was determined by visual observation, after allowing the fluidsto stand for about an hour.

The results are reported in TABLE 2, where the “Z” following the fluidnumber indicates that the fluid comprises zeolite, and the “O” or “W”indicates whether the fluid is water-based or oil-based. TABLE 2Rheological Data (at Dial Readings) 600 300 200 100 6 3 PlasticViscosity Yield Point Fluid No. rpm rpm rpm rpm rpm rpm (centipoise)(lb/100 ft²) Settling 1 (W) 24 18 15 12 11 10.5 6 12 None 2 (W) (Z) 6042 35 27 12 10 18 24 None 3 (W) (Z) 47 34 29 22 9 8 13 21 None 4 (W) 6446 39 30 14 11 18 28 None 5 (W) (Z) 58 40 32.5 24.5 10 8.5 18 22 None 6(O) 57 39 31 23 11 10 18 21 None 7 (O) (Z) 114 61 43 23 1.5 1 53 8 None

Comparing the data for the lime and water-based fluids, (Fluids 1-3),Table 2. shows that lime and water-based fluids with zeolite (e.g.,Fluids 2 and 3) attain favorable yield points as compared to lime andwater-based fluids without zeolite (e.g, Fluid 1). In addition, theplastic viscosity values of Fluids 2 and 3 are within acceptableparameters for use as a drilling fluid.

Comparing the data for the gel and water-based fluids, (Fluids 4-5),Table 2 shows that gel and water-based fluids with zeolite (e.g., Fluid5) attain yield points and plastic viscosities comparable to those ofgel and water-based fluids without zeolite (e.g, Fluid 4), and which arewithin acceptable parameters for use as a drilling fluid.

Thus, when zeolite is substituted for a suspension agent, (such as thebentonite viscosifier in Fluids 1 and 4), in a water-based drillingfluid, the zeolite contributes acceptable suspension properties to thedrilling fluid.

Comparing the data for the oil-based fluids, (Fluids 6-7), Table 2 showsthat oil-based drilling fluids with zeolite (e.g., Fluid 7) attain yieldpoints and plastic viscosities within acceptable parameters for use as adrilling fluid. Thus, when zeolite is substituted for a suspensionagent, (such as the GELTONE II viscosifier in Fluid 6), in an oil-baseddrilling fluid, the zeolite contributes acceptable suspension propertiesto the drilling fluid.

As to whether water and oil based drilling fluids including zeolite hadenough suspension properties to prevent settling, the testing involvedallowing the fluids to stand for about an hour. After an hour, settlingwas not observed in any of Fluids 2, 3, 5 and 7, further indicating theability of the zeolite to provide properties to the fluid sufficient tomaintain a suspension.

Thus, Table 2 shows that zeolite is a suitable suspension agent, and canbe used instead of, or in addition to, conventional suspension agents,such as viscosifiers.

EXAMPLE 3

Acceptable values of gel strength, gel plateau, filter cake thicknessand filtrate loss are relevant in order to provide a drilling fluid withthe properties required for use in drilling operations. The fluids fromExample 1 were tested to determine gel strength, filter cake thicknessand filtrate, in order to illustrate that drilling fluids comprisingzeolite not only have acceptable suspension properties, but also attainacceptable values of gel strength, gel plateau, filter cake thicknessand filtrate loss. The results are reported in TABLE 3, where the “Z”following the fluid number indicates that the fluid comprises zeolite,and the “O” or “W” indicates whether the fluid is water-based oroil-based.

The gel strength values for Fluids 1-5 were determined according toSection 2 of API Specification RP 13B, 12^(th) Edition, 1988, of theAmerican Petroleum Institute (the entire disclosure of which is herebyincorporated as if reproduced in its entirety). The gel strength valuesfor Fluids 6-7 were determined according to Section 2 of APISpecification RP 13B-2, 2^(nd) Edition, 1991, of the American PetroleumInstitute (the entire disclosure of which is hereby incorporated as ifreproduced in its entirety). The reported value for Gel Strength Plateauof each fluid is the difference between the gel strength at 10 secondsand the gel strength at 10 minutes. Generally, low plateau values (i.e.,less difference between the gel strength at 10 seconds and the gelstrength at 10 minutes) are desired.

The filter cake and filtrate loss values for Fluids 1-5 were determinedaccording to Section 3 of API Specification RP 13B, 12^(th) Edition,1988, of the American Petroleum Institute (the entire disclosure ofwhich is hereby incorporated as if reproduced in its entirety). Thefilter cake and filtrate loss values for Fluids 6-7 were determinedaccording to Section 3 of API Specification RP 13B-2, 2^(nd) Edition,1991, of the American Petroleum Institute (the entire disclosure ofwhich is hereby incorporated as if reproduced in its entirety).Generally, thinner filter cakes and lower filtrate loss values arepreferred. TABLE 3 Gel Strength at Time Filter Cake (lb/100 ft²) GelStrength Thickness Filtrate Loss Fluid No. 10 sec 10 min Plateau(inches) (cc/30 min) 1 (W) 12 21 9 7/32″ 32 2 (W) (Z) 14 21 7 4/32″ 36 3(W) (Z) 10 15 5 4/32″ 32 4 (W) 15 22 7 1/32″ 8.5 5 (W) (Z) 10 17 7 5/32″36 6 (O) 10 11 1 2/32″ 3.5 7 (O) (Z) 3 3 0 5/32″ 3

Comparing the data for the lime and water-based fluids, (Fluids 1-3),Table 3 shows that lime and water-based fluids with zeolite (e.g.,Fluids 2 and 3) attain gel strengths and gel plateaus comparable tothose of lime and water-based fluids without zeolite (e.g, Fluid 1). Thefilter cake thickness and filtrate loss data are also comparable forFluids 1-3.

Comparing the data for the gel and water-based fluids, (Fluids 4-5),Table 3 shows that gel and water-based fluids with zeolite (e.g., Fluid5) attain gel strengths and gel plateaus comparable to those of gel andwater-based fluids without zeolite (e.g, Fluid 4). The filter cakethickness and filtrate loss values for Fluid 5 are within acceptableparameters for use as a drilling fluid.

Thus, when zeolite is substituted for a suspension agent, (such as thebentonite viscosifier in Fluids 1 and 4), in a water-based drillingfluid, additional properties of the drilling fluid are also acceptable,as illustrated by the data in Table 3.

Comparing the data for the oil-based fluids, (Fluids 6-7), Table 3 showsthat oil-based drilling fluids with zeolite (e.g., Fluid 7) attainimproved gel strengths and gel plateaus over those of oil-based drillingfluids without zeolite (e.g., Fluid 6). The filter cake thickness andfiltrate loss data are comparable for Fluids 6 and 7.

Thus, when zeolite is substituted for a suspension agent, (such as theGELTONE II viscosifier in Fluid 6), in an oil-based drilling fluid,additional properties of the drilling fluid are also acceptable, asillustrated by the data in Table 3.

EXAMPLE 4

Example 4 illustrates that fluids comprising zeolite develop compressivestrength in the presence of a compressive strength-developing amount ofactivator, such as lime (also referred to as calcium hydroxide).

Four mixes were prepared by combining the components as set forth inTABLE 4 below. Specifically, the zeolite and the lime were dry-mixed byhand in a glass jar. This dry mix was then added over a 15 second periodto a carrier fluid (water, in this example) being maintained in a Waringblender at 4,000 RPM. The blender speed was then increased to 12,000 RPMand mixing was continued for 35 seconds. The amount of lime and waterused to form each mix is reported in the table as a “% bwoZ”, whichindicates a weight percent based on the weight of the zeolite.Chabazite, which is commercially available from C2C Zeolite Corporationof Calgary, Canada, was used as the zeolite for each mix.

The compressive strength for each mix was determined by Non-DestructiveSonic Testing as set forth in API Specification 10B 22nd Edition, 1997,of the American Petroleum Institute, the entire disclosure of which isincorporated herein by reference as if reproduced in its entirety. Thecompressive strength was measured at 160° F. at the reported elapsedtimes, and is reported in pounds per square inch (psi).

Although the mixes of Example 4 include only zeolite, water, and lime,the mixes are indicative of the expected reaction when a drilling fluidthat includes zeolite comes into contact with an activator, such ascalcium hydroxide. Thus, portions of a drilling fluid comprising zeolitethat remain in filter cake on a wall of a wellbore, or in permeableareas in the wellbore, can be caused to set by circulation of asubsequent fluid containing an activator, which comes into contact withthe zeolite. TABLE 4 Compressive Components strength (psi) at 160° F.Mix Zeolite Lime Water 4 8 12 24 No. (wt %) (% bwoz) (% bwoz) Hr Hr HrHr 1 100 7 106 0 0 0 0 2 100 10 109 280 290 290 290 3 100 15 114 500 540568 568 4 100 35 136 500 700 730 750

The compressive strength data for the mixes in Table 4 indicates that adrilling fluid comprising zeolite would develop compressive strengthwhen the amount of an activator, such as lime, is present in an amountgreater than about 7% based on the weight of the zeolite. Thus, portionsof a drilling fluid comprising zeolite that remain in filter cake on awall of a wellbore, or in permeable areas in the wellbore, can be causedto set by circulation of a subsequent fluid containing an activator in acompressive strength-developing amount.

In designing a drilling fluid that includes zeolite, the identity of thezeolite and the carrier fluid may influence the amount of activatornecessary for the development of compressive strength. In addition, theidentity of the activator may influence the amount of activatornecessary for the development of compressive strength. Thus, in someembodiments, a compressive strength-developing amount of activator isless than the 7% illustrated by Example 4. Accordingly, the amount ofactivator used in practicing the present embodiments need only be atleast a compressive strength-developing amount. Those of ordinary skillin the art can determine through the exercise of routine experimentationthe amount of an activator sufficient for the development of compressivestrength.

The development of compressive strength in the mixes of Example 4 wascaused by the lime, also known as calcium hydroxide, which is a knownactivator for converting settable material in conventional settablespotting fluids. Thus, Example 4 illustrates that when an activator,such as lime, is brought into contact with a drilling fluid comprisingzeolite the activator will cause the zeolite to set.

Contact between an activator and zeolite-containing drilling fluidremaining in a wellbore can be accomplished by various methods. Theaddition of the lime and zeolite together in the mixes as described inExample 4 simulates two of the various methods suitable for bringing anactivator into contact with the zeolite. According to the first methodsimulated by this example, zeolite from a drilling fluid remains on thewalls of the wellbore as part of the filter cake, and/or in permeableareas affecting the wellbore, such as fissures, fractures, caverns,vugs, thief zones, low pressure subterranean zones or high pressuresubterranean zones. An activator is brought into contact with thezeolite remaining in the wellbore by circulation of a subsequentcomposition, such as a pill, spotting fluid or other mud, which containsthe activator. According to the second method simulated by this example,an activator is brought into contact with the zeolite remaining in thewellbore by diffusion of an activator contained in a cement slurry thatis subsequently pumped into the wellbore during primary cementingoperations.

The two methods simulated by Example 4 are exemplary only, as a varietyof methods for bringing a settable material into contact with anactivator are suitable for use with the present embodiments.

While the preferred embodiments described herein relate to drillingfluids, it is understood that any wellbore treating fluids such asdrilling, completion and stimulation fluids including, but not limitedto, drilling muds, cement compositions well cleanup fluids, workoverfluids, spacer fluids, gravel pack fluids, acidizing fluids, fracturingfluids and the like can be prepared using zeolite and a carrier fluid.

Preferred methods of performing drilling operations comprise circulatinga drilling fluid comprising a carrier fluid and zeolite in a wellbore ina subterranean formation. Additional steps can include completing and/orstimulating a subterranean formation using the drilling fluid andproducing a fluid, e.g., a hydrocarbon fluid such as oil or gas, fromthe subterranean formation.

Other embodiments of the current invention will be apparent to thoseskilled in the art from a consideration of this specification orpractice of the invention disclosed herein. However, the foregoingspecification is considered merely exemplary of the current inventionwith the true scope and spirit of the invention being indicated by thefollowing claims.

1. A fluid comprising zeolite and a carrier fluid, wherein the zeoliteis selected from analcime, bikitaite, brewsterite, chabazite,clinoptilolite, faujasite, harmotome, heulandite, laumontite, mesolite,natrolite, paulingite, phillipsite, scolecite, stellerite, stilbite, andthomsonite.
 2. The fluid of claim 1 wherein the fluid comprises zeolitein an amount from about 1% to about 50% by volume.
 3. The fluid of claim1 wherein the fluid comprises zeolite in an amount from about 5% toabout 20% by volume.
 4. The fluid of claim 1 wherein the fluid compriseszeolite in an amount from about 8% to about 15% by volume.
 5. The fluidof claim 1 further comprising at least one weighting agent.
 6. The fluidof claim 5 wherein the weighting agent is selected from barite,hematite, manganese tetraoxide, ilmenite, calcium carbonate and galena.7. The fluid of claim 5 wherein the weighting agent is present in anamount of up to about 97% by volume of the fluid.
 8. The fluid of claim5 wherein the weighting agent is present in an amount of from about 2%to about 57% by volume of the fluid.
 9. The fluid of claim 1, furthercomprising a viscosifier.
 10. The fluid of claim 1, further comprising afiltrate loss control agent comprising cellulose, and wherein thecellulose is present in an amount of from about 0.01% to about 2.5% byvolume.
 11. The fluid of claim 9, wherein the viscosifier is present inan amount of up to about 5% by volume.
 12. The fluid of claim 9, whereinthe viscosifier is selected from clays, polymeric additives, modifiedcellulose and derivatives thereof, guar gum, emulsion forming agents,diatomaceous earth and starches.
 13. The fluid of claim 12 wherein theviscosifier comprises a clay selected from kaolinite, montmorillonite,bentonite, hydrous micas, attapulgite, sepiolite, and laponite.
 14. Thefluid of claim 12 wherein the viscosifier comprises a polymeric additivethat contains one or more hydroxyl, cis-hydroxyl, carboxyl, sulfate,sulfonate, amino or amide functional groups.
 15. The fluid of claim 12wherein the viscosifier comprises a polymeric additive comprisingpolysaccharide and derivatives thereof which contain one or more of thefollowing monosaccharide units: galactose, mannose, glucoside, glucose,xylose, arabinose, fructose, glucuronic acid or pyranosyl sulfate. 16.The fluid of claim 12 wherein the viscosifier comprises a polymericadditive selected from guar gum and derivatives thereof, locust beangum, tara, konjak, starch, cellulose, karaya gum, xanthan gum,tragacanth gum, arabic gum, ghatti gum, tamarind gum, carrageenan andderivatives thereof, carboxymethyl guar, hydroxypropyl guar,carboxymethylhydroxypropyl guar, polyacrylate, polymethacrylate,polyacrylamide, maleic anhydride, methylvinyl ether copolymers,polyvinyl alcohol and polyvinylpyrrolidone.
 17. The fluid of claim 12wherein the viscosifier comprises a modified cellulose selected fromcarboxyalkylcellulose ethers, mixed ethers, hydroxyalkylcelluloses,alkylhydroxyalkylcelluloses, alkylcelluloses,alkylcarboxyalkylcelluloses, alkylalkylcelluloses andhydroxyalkylalkylcelluloses.
 18. The fluid of claim 17 wherein theviscosifier is selected from carboxyethylcellulose,carboxymethylcellulose, carboxymethylhydroxyethylcellulose;hydroxyethylcellulose, hydroxypropylcellulose,methylhydroxypropylcellulose, methylcellulose, ethylcellulose,propylcellulose, ethylcarboxymethylcellulose, methylethylcellulose, andhydroxypropylmethylcellulose.
 19. The fluid of claim 12 wherein theviscosifier is selected welan gum, xanthan gum, galactomannan gums,succinoglycan gums, scleroglucan gums, and cellulose and itsderivatives.
 20. The fluid of claim 1, further comprising at least onedispersant.
 21. The fluid of claim 20, further comprising at least onedispersant selected from the group consisting of sulfonated styrenemaleic anhydride copolymer, sulfonated vinyltoluene maleic anhydridecopolymer, sodium naphthalene sulfonate condensed with formaldehyde,sulfonated acetone condensed with formaldehyde, lignosulfonates andinterpolymers of acrylic acid, allyloxybenzene sulfonate, allylsulfonate and non-ionic monomers.
 22. The fluid of claim 20 furthercomprising from about 0.2% to about 6% by volume of dispersant.
 23. Thefluid of claim 1, wherein the carrier fluid is selected from aqueousfluids, water, water-based gels, oil-based fluids, synthetic-basedfluids, emulsions, acids, or mixtures thereof.
 24. The fluid of claim 23wherein the carrier fluid comprises water selected from fresh water,unsaturated salt solution, brine, seawater, and saturated salt solution.25. The fluid of claim 23 wherein the carrier fluid comprises anoil-based fluid selected from canola oil, kerosene, diesel oil, fishoil, mineral oil, sunflower oil, corn oil, soy oil, olive oil,cottonseed oil, peanut oil and paraffin.
 26. The fluid of claim 1,wherein the carrier fluid is present in an amount of from about 3% toabout 98% by volume of the fluid.
 27. The fluid of claim 1, wherein thecarrier fluid is present in an amount of from about 50% to about 92% byvolume of the fluid.
 28. The fluid of claim 1, wherein the carrier fluidis present in an amount of from about 80% to about 90% by volume of thefluid.
 29. The fluid of claim 1, further comprising at least one of asurfactant, an emulsifier, a foaming agent, a de-air entraining agent,loss circulation material, and a lubricant.
 30. A compositioncomprising: a first fluid and a second fluid, wherein the first fluid islocated in a subterranean zone, and comprises at least one carrierfluid, and a zeolite selected from analcime, bikitaite, brewsterite,chabazite, clinoptilolite, faujasite, harmotome, heulandite, laumontite,mesolite, natrolite, paulingite, phillipsite, scolecite, stellerite,stilbite, and thomsonite, and the second fluid comprises a compressivestrength-developing amount of an activator; wherein the composition isformed when the second fluid contacts the first fluid in thesubterranean zone.
 31. The composition of claim 30, wherein the secondfluid comprises one of a cement slurry, a mud, a spotting fluid, and apill comprising a compressive-strength developing amount of anactivator.
 32. The composition of claim 30, wherein the activator isselected from calcium hydroxide, sodium silicate, sodium fluoride,sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride,sodium carbonate, potassium carbonate, sodium hydroxide, potassiumhydroxide, sodium sulfate, and mixtures thereof.
 33. The composition ofclaim 30, wherein the activator is present in the second fluid in aweight percent greater than about 7 percent of the weight of the zeolitein the first fluid.
 34. The composition of claim 30, wherein the zeoliteis selected from analcime, bikitaite, brewsterite, chabazite,clinoptilolite, faujasite, harmotome, heulandite, laumontite, mesolite,natrolite, paulingite, phillipsite, scolecite, stellerite, stilbite, andthomsonite.
 35. The composition of claim 30, wherein the first fluidcomprises zeolite in an amount from about 1% to about 50% by volume. 36.The composition of claim 30, wherein the first fluid comprises zeolitein an amount from about 5% to about 20% by volume.
 37. The compositionof claim 30, wherein the first fluid comprises zeolite in an amount fromabout 8% to about 15% by volume.